This invention addresses the problem of determining the three-dimensional (3D) distribution of hydrocarbon fluids within a subsurface reservoir, which often will be located beneath a body of water such as beneath the sea, during the time period (or periods) of hydrocarbon production from that reservoir Applications of seismic methods to this problem are called time-lapse or 4D methods. A critical issue for economical production of hydrocarbons (gas, gas condensate, and oil) from reservoirs is accurate knowledge of the distribution of hydrocarbon saturation within the porous rocks that comprise the reservoir. As hydrocarbons are produced from the reservoir, the hydrocarbon saturation decreases and the water saturation increases in a non-uniform manner within the reservoir. Although seismic methods have been developed for 4D applications to monitor reservoir fluids, such methods are expensive, and are often ineffective due to the relatively low sensitivity of the seismic response to changes in hydrocarbon saturation. Such low sensitivity is particularly true for oil reservoirs, because the acoustic properties of most oils are very similar to those of the reservoir formation waters and thus changes in oil saturation are not reflected in the seismic response.
Other methods are known in the art for estimating reservoir fluid properties. Hydrocarbon resistivity and saturation data are available during reservoir depletion from borehole (downhole or well log) methods within a few meters of the wellbore. However, well logging methods are not effective between wells that are usually spaced hundreds to thousands of meters apart as found in many hydrocarbon fields, due to the limited penetration distance of the probing signals into the reservoir from the downhole well logging apparatus. In addition, production wells are usually enclosed with electrically conductive casing, which severely limits the use of electrical methods to monitor reservoir fluid resistivity since the reservoir is shielded from the electrical probing signal by the casing (except at very low frequency).
Reservoir fluid resistivity and saturation data are also available during reservoir depletion from cross-borehole (crosswell) methods, using seismic or electromagnetic energy (c.f. Rector, W. J. (ed.), “Crosswell Methods: Special Issue”, Geophysics 60, no. 3 (1995)). However, crosswell methods require at least two wells to be used simultaneously for the measurement, which is expensive since production from both wells must be stopped and the production tubing must be removed from the wells. In addition, crosswell data provide primarily two-dimensional measurements in the common vertical plane that connects the measurement wells. Most wells in sub-sea reservoirs are deviated from the vertical, which limits the amount of common vertical plane between well pairs. Also, crosswell methods are not effective between wells that are usually spaced hundreds to thousands of meters apart as found in many hydrocarbon fields, due to the limited penetration distance of the probing signals from the downhole source. And in a similar fashion to the single-well logging case, the presence of electrically conductive casing in production wells severely limits the ability to use crosswell electrical methods to detect reservoir fluid resistivity.
Another method that is used routinely to estimate fluid saturation between wells is the mathematical simulation of reservoir fluid flow. However reservoir simulation necessarily incorporates many simplifications and assumptions about the properties of the rocks between the wells, in order to make the mathematical simulation practical on even a large computer. Reservoir simulation also requires continual adjustment of numerical parameters in the model to match the data measured in wells, the so-called “history matching” approach, and these parameters may not have a simple connection to measured rock and fluid properties.
Results from offshore controlled-source electromagnetic (“CSEM”) surveys, such as those collected using the methods disclosed in U.S. Pat. No. 4,617,518 to Srnka and the previously referenced U.S. Pat. No. 6,603,313 and U.S. Patent Publication No. 2003/0050759, have shown that the bulk resistivity of fluids in hydrocarbon reservoirs can be determined remotely. To a good first approximation, marine CSEM data obtained using a horizontal electric dipole (HED) source are primarily sensitive to the net vertical resistance (bulk resistivity times net vertical thickness) of the subsurface reservoir (Kaufman and Keller, Frequency and Transient Soundings, 300-313, Elsevier (1983)). A survey offshore West Africa (Eidesmo, et al., First Break, 20, 144-152 (2002); Ellingsrud et al., The Leading Edge, 972-982 (2002)) confirmed that subsurface resistivity caused by the presence of hydrocarbons can be detected.
It is known that the earth's electrical resistivity can be aniostropic. See, for example, Keller and Frischnecht, Electrical Methods in Geophysical Prospecting, 33-39, Pergamon (1966); Kaufmann and Keller, Frequency and Transient Soundings, 257-284, Elsevier, N.Y. (1983); Negi, et al., Anisotropy in Geoelectromagnetism, Elsevier, N.Y. (1989); and Zhdanov and Keller, The Geoelectrical Methods in Geophysical Exploration, 119-124, Elsevier, N.Y. (1994). Several publications teach how to calculate (model) the anisotropic earth electrical responses for various controlled sources. See, for example, Chlamtac and Abramovici, Geophysics 46, 904-915 (1981); Yin and Weidelt, Geophysics 64, 426-434 (1999); Yin and Maurer, Geophysics 66, 1405-1416 (2001). Also, several authors discuss the interpretation of azimuthal electrical anisotropy (for example, Watson and Barker, Geophysics 64, 739-745 (1999); and Linde and Peterson, Geophysics 69, 909-916 (2004)). Others discuss the interpretation of anistropy (Jupp and Vozoff, Geophys. Prospecting 25, 460-470 (1977); Edwards, et al., Geophysics 49, 566-576 (1984); and Christensen, Geophys. Prospecting 48, 1-9 (2000)) from data acquired using a variety of controlled electromagnetic sources.
U.S. Pat. No. 6,739,165 to Strack discloses a method to monitor changes in the electrical resistivity of a reservoir by measuring changes in electric and magnetic field data at the earth's surface, due to excitations by controlled galvanic and inductive sources and by natural magnetotelluric sources, that must include measuring resistivity changes in at least one wellbore that penetrates the reservoir. Strack does not disclose the use of imaging or inversion to map the distribution of bulk reservoir resistivity ρr or hydrocarbon saturation Shc, and does not discuss electrical anisotropy.
Johnstad, et al., in patent publication No. WO 2004/086090, disclose a method for reservoir resistivity monitoring similar to Strack, but which includes a downhole electromagnetic source that is constructed by transmitting electrical energy from the seafloor into the reservoir through the electrically conductive casing that lines the well. The authors do not disclose the use of 3D imaging or 3D inversion to determine ρr or Shc, and do not disclose how to include the effects of electrical anisotropy.
Constable, in patent publication WO 2004/053528 (2004), A1, discusses a method for real-time monitoring of hydrocarbon reservoirs. He proposes using various vertical and horizontal electric dipole sources and natural electromagnetic (e.g. magnetotelluric) sources, singly or in combinations, together with seafloor antennas containing electric and magnetic sensors in various arrays distributed over an area containing a hydrocarbon reservoir. The seafloor antennas can be permanently fixed to the seafloor or can be emplaced separately at several times. Constable's method for monitoring time changes in the bulk electrical resistivity ρr of the reservoir consists of measuring the electrical impedance of the earth at each source-receiver combination, using the two orthogonal horizontal and the vertical electric field components of the receiver signals that are responsive to the energy from the transmitter, and mapping these impedances over the area of the reservoir. The magnetotelluric data can be used optionally to help determine the electrical background (non-reservoir volume of the earth). No mathematical inversion or imaging of the receiver signals, of any dimensionality, and no method for including the effects of anisotropy, are disclosed.
Loke (“Constrained Time-Lapse Resistivity Imaging Inversion”, paper EEM-7, Proceedings of the SAGEEP Symposium, Denver, Mar. 3-7, 2001) describes the use of 2D constrained imaging inversion to measure time changes in subsurface resistivity for environmental applications. Loke discloses the use of the resistivity inversion result obtained at the initial survey time as a starting model for the resistivity inversion performed at a later time, in order to reduce artifacts in the result that may be introduced by effects other than changes in subsurface resistivity, such as acquisition system changes. This publication limits its discussion to DC resistivity surveys, and uses a data example obtained from an onshore Wenner-Schlumberger array, a survey method well known to practioners of the art. No anisotropic effects are discussed by Loke, nor does Loke discuss offshore data, the use of multiple components of the data, or hydrocarbon applications.
Gasperikova, et al. (“A Feasibility Study of Geophysical Methods for Monitoring Geologic CO2 Sequestration”, Extended Abstract RC 3.8, SEG Annual Meeting, Denver, Colo., October 2004) discuss the use of onshore electric field measurements associated with excitation by a grounded HED source to measure the change in water saturation (or 1-Shc) in the Schrader Bluff field on the North Slope of Alaska as a consequence of CO2 injection, based on 3D forward modeling. Time-dependent changes are simulated by differencing the forward model calculations at the appropriate times. The paper does not describe which component(s) of the electric field are optimal for this measurement, nor are any anisotropic effects discussed.
Hoversten, et al. (“Direct Reservoir Parameter Estimation using Joint Inversion of Seismic AVO and marine CSEM Data”, Extended Abstract RC 2.1, SEG Annual Meeting, Denver, Colo., October 2004) disclose a method for 1D (plane-layered earth) simultaneous inversion of seismic reflection and marine CSEM seafloor data (HED source). The CSEM data are restricted to inline online electric field data (i.e. Ex on the source line, see FIG. 1). Hoversten et al. (2004) do not teach time lapse methods for reservoir monitoring, nor do they teach how to include earth electrical anisotropy in the inversions.
Accordingly there is a need for a method to directly estimate the hydrocarbon saturation throughout the reservoir in a 3D sense by remotely measuring and imaging a subsurface physical parameter that is highly sensitive to that saturation, and to be able to repeat that measurement/imaging and analyze the data as the reservoir fluids are produced. Such a method must account for resistivity anisotropy. The present invention satisfies this need.